The present invention relates to an improved system and process for separation of a mixture of oil and water from gas and separation of the mixture into its constituents in petroleum production facilities under circumstances where either the space occupied by the separation system or the weight of that system are important economic or engineering considerations or where the system is subject to motion. Offshore floating and fixed structures for the production of petroleum and gas, and production structures for use in arctic environments are examples of such circumstances.
In present gas and oil drilling and recovery practice, a gas, oil and water mixture is brought from the well and typically is sent to a high pressure, first stage, separator where gas and liquid are separated, then the liquid fraction, containing a reduced portion of gas, is sent to a medium-pressure, second stage separator where more gas is removed, and then the liquid fraction from the second stage separator, still containing some gas flows into a low-pressure, third stage separator where additional gas is withdrawn and a rough-cut separation of oil and water is made.
An alternate conventional third-stage separation may be accomplished by use of two vessels, the first having a short liquid residence time to separate gas from the liquid phase and the second having a longer liquid residence time to separate oil and water. In either case, the nominal liquid residence time for the oil/water separation is about 20 minutes, with a 10 to 30 minute range being typical. Water which is produced from either type of third stage separation system typically contains about 2000 to 5000 ppmv of free oil. By use of the term free oil we mean oil in the water phase which is not dissolved.
This water from the third stage separation then typically goes to a corrugated plate interceptor (CPI) separator which also has a residence time of about 20 minutes. Water exiting the CPI separator typically has a free oil content of approximately 100 to 200 ppmv. In some applications, this last stage of separation would be the final separation for water processing. However, in many instances where water may not be discharged to the environment with 200 ppmv of free oil, the water is then sent to a dispersed gas flotation (DGF) separator for another, final purification step. In the DGF separator a gas is used to coalesce much of the remaining free oil. Through use of the DGF separator, the water is typically purified to about 35 ppmv free oil for most applications, to about 20 ppmv free oil, in the event the water is to be released into carefully regulated environments, such as California waters and to about 10 ppmv free oil if it is to be reinjected into the producing formation so that normally installed filters will not be plugged.
In typical conventional systems the oil from the third stage separator is normally shipped "wet", that is, without further removal of water. This wet oil separated in the third stage separator typically contains approximately 3-5% by weight water and sometimes as much as 10% by weight. Water droplets in the oil are usually about 500 microns in size.
Occasionally the suspended water must be removed from the oil (dewatering of oil) prior to leaving the production site facilities for either corrosion control or to meet a particular pipeline specification. The dewatering is typically done by means of an electrostatic dehydration vessel. This is a large liquid filled vessel with internal electrodes which electrically break the surface tension between the oil and water droplets. This process usually requires the addition of chemical demulsifiers to assist in the separation and typically reduces the water content to between 0.1 and 0.5 percent by weight. When the production facility is located offshore, such electrostatic precipitators are usually located onshore because of their large size and weight. However, in situations where an offshore facility must send the oil to a pipeline in which high purity, or "spec" oil is carried, then dewatering of the oil must be accomplished offshore.
Thus, it can be seen that conventional systems make extensive use of large vessels to achieve each of the gas/oil/water separations. In these systems, the settling and electrostatic precipitator vessels are made large to provide substantial retention time and are heavy because they contain a substantial amount of liquid during normal operations. Also, such vessels lose some of their effectiveness and must be made even larger when subject to motion, as on a floating production system. Two major advantages of systems of the present invention are (i) that they will occupy considerably less space and will weigh much less than conventional systems, and (ii) that they are insensitive to motion. It is anticipated that as a result the size, weight and therefore total cost of gas and petroleum production structures may be significantly reduced.